The present invention relates generally to the oil and gas industry and in particular to stripper well production utilizing reciprocating pumps.
Marginal oil wells, better known as stripper wells, are rarely operated by major oil companies because labor and pumping costs are close to the sales revenue produced by the well, which makes their operation uneconomic. Most oil and gas wells will slowly reduce its hydrocarbon output and finally end up as stripper wells. At this point, major companies will attempt to sell these wells to small companies or plug and abandon the well. Entrepreneurs who are able to scrounge up enough equipment and control their labor and operating costs operate these small companies; however, even their operating costs will slowly mount and the well will be abandoned.
The actual definition of a stripper well is difficult to come by, mainly because one person""s (or company""s) idea of a stripper well will differ from another""s. Generally a well is considered to be a stripper well when it produces less than 10 barrels (420 U.S. gallons) of hydrocarbons per day. Stripper wells are important to the economy of any country for they allow that country to depend less on foreign supplies of hydrocarbons. This is particularly important in times of international political unrest.
With this in mind, it is desirable to develop and have available novel oil well production equipment that is relatively inexpensive and can be assembled from commercially available materials. Novel equipment will allow an increase in the profit gleaned from a stripper well. Novel equipment should have several design points in mind. One, it should be easy to work on and maintain. Two, it should be capable of operating at a low cost. Three, it should operate the stripper well in such a manner that the production rate will increase from marginal to profitable. Thus, properly designed novel production equipment will increase the number of profitable stripper wells and increase the overall supply of valuable hydrocarbons.
Many stripper wells use a pump-jack unit that in turn reciprocates a bottom hole pump. However, in a stripper, the flow of fluid into the wellbore is limited (hence the term xe2x80x9cstripperxe2x80x9d), and it is possible to run out of fluid. This condition is called xe2x80x9cpump-off.xe2x80x9d Pump-off occurs whenever the pump system attempts to remove more fluid from the wellbore than is entering the wellbore from the producing formation. Pump-off leads to destruction of the downhole pump, the surface drive unit, and the intermediate connection between the downhole pump and the surface unit. The actual mechanism that causes destruction is termed xe2x80x9cfluid pounding.xe2x80x9d
Fluid pounding is encountered whenever pump-off occurs. The lack of fluid in wellbore allows the introduction of compressible gases into the wellbore. These gases generally come from the formation or xe2x80x9coutgasxe2x80x9d from the wellbore fluid.
The downhole reciprocating pump consists of essentially two parts, a moving chamber or pump plunger within a downhole assembly or pump barrel. The pump barrel is attached to the production tubing, which runs inside the wellbore to the surface. The pump plunger lifts fluid from within the pump barrel into the production tubing and onto the surface. On the upstroke, the plunger chamber inlet valve is closed and fluid flows into the production tubing making its way to the surface; whereas, on the downstroke, the inlet valve is open. On the up stroke, wellbore fluids flow into the pump barrel through a valve, at its base, that opens on the upstroke and closes on the down stroke.
In normal circumstances, the pump plunger operates within a liquid. The liquid in turn provides damping to the plunger, on the downstroke, that absorbs the extension of the interconnection assembly between the plunger and the surface power unit. The interconnection assembly is generally a series of coupling rodsxe2x80x94named xe2x80x9csucker rods.xe2x80x9d The interconnection assembly could easily be a wire cable. Materials expand (and contract) under load; thus, the interconnection assembly will elongate under load. Under usual circumstances, the downhole fluid absorbs the elongation.
Whenever pump-off occurs the pump accelerates into a gas rather than a fluid on the downstroke of the pump. There is little liquid to absorb or dampen the elongation, and the plunger strikes or pounds the bottom portion of the pump barrel. Hence the termxe2x80x94fluid pounding. The bottom of the plunger and the bottom of the barrel both contain fluid inlet/check valves. Fluid pounding ruins both valves. It also damages the interconnection assembly and the surface power unit. Much consideration must be given to avoid pump-off or fluid pounding.
There is one other cause of fluid pump-off. Many oil wells which are in the their maturity begin to produce gas along with the oil. This often results in fluid pounding even though the well is not pumping-off. Quite often these wells are shut down, simply because the cost of production, due to equipment problems, exceeds or reaches the revenue derived from the well.
In the current art, the pump barrel inlet (check) valve (sometimes called the standing valve), and the pump plunger inlet valve and outlet check valve (sometimes called the traveling valve) must operate against the wellbore hydrostatic head. Thus, when the plunger lifts up, its inlet valve closes, and the barrel inlet valve opens. The reduced pressure within the pump barrel caused by the raising of the plunger allows the inlet valve to open. At this point, formation fluid will enter the barrel. In a marginal well, this fluid is a gas-liquid fluid, which is compressible. On the down stroke, the barrel check valve will close. If the barrel fluid is incompressible (i.e., no entrained gas), then the increase pressure within the barrel, below the plunger, will force the outlet valve of the plunger to open as the plunger approaches the bottom of the pump barrel.
It must be remembered that as the plunger starts down, the fluid pressure below the plunger within the barrel is at or near formation pressure, which is lower than the hydrostatic head pressure above the plunger outlet valve. Thus, the outlet valve will not open until the pressure inside the pump barrel, below the plunger, exceeds the hydrostatic pressure of the wellbore. As the quantity of entrained gas builds up within the pump barrel below the plunger, the pressure within the pump barrel below the plunger will never exceed the hydrostatic head and the outlet and inlet valves on the plunger will not open. This is pump-off. Because there is little liquid to soften the downstroke, pounding occurs.
Madden in U.S. Pat. RE. 33,163 (4,781,547) discloses a Gas Equalizer for Downhole Pump. The Madden device operates in conjunction with the traveling valve. Basically the Madden device is designed to be fitted to an ordinary downhole pump and unseats the traveling ball check valve, or outlet check valve, during most of the downstroke of the plunger. In other words, the Madden device forces the upper check valve to open without relying on the increase in pressure within the plunger to force the valve open. Madden states that, by forcing the upper check valve to open, compressible fluid (gas) will be removed from the variable pump chamber on each downstroke of the pump. This then allows the gas to bubble through the production tubing to the surface. The Madden device cannot relieve the downhole liquid column pressure (wellbore hydrostatic head) on the downhole pump. Thus there is a limit to the suitability of the Madden device.
Heath, U.S. Pat. No. 2,949,861 discloses a Pumping Rig and Method. This device utilizes a downhole traveling valve; however, Heath is only concerned with reducing the effective weight of the sucker rods and does not address pounding or production problems associated with wellbore hydrostatic head.
The economic factors influencing the abandonment of a hydrocarbon well include operating costs, environmental issues, costs of abandonment, etc. Operating costs are set by many factors: labor price, distance from a maintenance base, available product distribution networks, workover cost, and equipment repair costs. The well must produce a profit. If any of the cost factors can be reduced, that well may become profitable. If maintenance is reduced, then the costs of labor and repair automatically come down. Since fluid pounding is a major maintenance headache in marginal wells, a technique to eliminate fluid pounding is needed. Thus there remains a need for a device that will reduce the effective wellbore hydrostatic head pressure and allow produced fluid to enter a downhole pump chamber.
The instant invention simply adds a valvexe2x80x94called a standing head valvexe2x80x94at the top of the pump barrel through which passes the lift connection (polished rod) that is attached to the pump plunger located within the barrel.
The standing head valve is designed to hold back the wellbore hydrostatic head pressure, contained within the production tubing, from the pump barrel (and the formation). Thus, at the start of the downstroke, the plunger valve only sees the formation pressure and readily opens to admit fluid. On the upstroke, the standing head valve is forced open, and the plunger fluid (formation fluid) passes through the standing valve into the wellbore. On the downstroke, the standing valve closes, and wellbore hydrostatic head pressure cannot be reflected into the pump barrel. Essentially, the standing head valve adds another check valve to the system.
The standing head valve is attached to the top of the pump barrel and a special smooth rod, or polished rod, passes through the center of the circular standing head valve. The polished rod attaches to the sucker rods that form the intermediate connection to the pump-jack on the surface. Of course other forms of intermediate connections could be used, e.g., a Cable Actuated Downhole Pump. (See for example the inventor""s co-pending application based on his Provisional Application 60/220,414, filed on Jul. 24, 2000.)
The valve has essentially two functioning parts, which are integrated. One of the parts is the special ring shaped, or circular, check valve and the other part is the seal system through which the polished rod passes. Because the standing head valve is circularxe2x80x94set by the barrel of a standard pump xe2x80x94a special check valve is required. The preferred circular check valve is plurality of spring loaded metal balls operating within a plurality of apertures set about the circular check valve. The seal system is simple and comprises a smooth long rod (polished rodxe2x80x94available off-the-shelf) with very close tolerances between the rod and the inner diameter of the metal-to-metal seal.
Although the disclosure shows the use of the circular check valve in a wellbore employed as a standing head check valve. The concept could readily be employed in a service that requires pressure control or flow control about a location through which a reciprocating or rotating member must pass.